Production streams produced by remote or marginal offshore oil and gas fields, in addition to hydrocarbons, often contain liquid water and water in the gas phase. The produced hydrocarbon-containing fluid is warm when leaving the wellhead, generally in the range of 60-130° C. and, if the fluid is transported untreated over long distances and allowed to cool below the hydrate formation temperature, then hydrates will form. Hydrates are sometimes also referred to as clathrate hydrates, gas clathrates, gas hydrates, or clathrates.
Hydrates are ice-like crystalline solids composed of water and gas. The hydrate formation temperature of a typically production stream is in the range of 20-30° C. for pressures of between 100-400 bar(a). Hydrate deposition on the inside wall of gas and oil pipelines is particularly problematic in offshore production infrastructure because, when a warm hydrocarbon fluid containing water flows through a subsea pipeline with cold walls, hydrates will precipitate and adhere to the inner walls. This will reduce the pipeline cross-sectional area, which, without proper counter measures, will lead to a loss of pressure and ultimately to a complete blockage of the pipeline or other process equipment. Subsea transportation of hydrocarbons over any significant distance therefore requires hydrate control.
There are various techniques used for short distance transportation, for example from the wellhead to an offshore processing hub. However, hydrate control for long distance transportation, such as back to land, is typically achieved by use of a hydrate inhibitor mixed with the produced hydrocarbon fluid and/or by removing water from the produced hydrocarbon fluid.
Multi-phase hydrocarbon fluids are often separated for transportation over long distances to avoid problems such as slugging. The present invention relates to the dehydration of a produced hydrocarbon gas phase stream.
The most common prior art method for achieving gas dehydration is by the aid of absorption, wherein water is absorbed by an absorbent or desiccant. The absorbent may be, for example, a glycol (e.g. monoethylene glycol, MEG, or triethylene glycol, TEG) or an alcohol (e.g. methanol or ethanol). These absorbents typically need a low water content level for use in absorption, and so a regeneration unit is required in order to remove water from the glycol or other absorbent to the levels required.
FIG. 1 illustrates an example of a prior art, topside or onshore gas dehydration process using absorption. In this process, wet natural gas 102 is introduced into the bottom of an absorber column 104, and cool, lean glycol 106 is sprayed into the top of the column 104. Water is absorbed from the natural gas as the glycol flows downwards and the gas upwards in the column 104. The dry natural gas 118 exits from the top of the column 104 and the used glycol 110, referred to as “rich glycol”, exits from the bottom of the column 104.
Water originating from the wet natural gas 102, now absorbed in the rich glycol 110, is then desorbed from the glycol in a separate process known as glycol regeneration. In the embodiment shown, this process is performed by distillation in a still 112, using low pressure and high temperature to vaporise the water, which is vented from the top of the still 112.
In order to achieve very high purity glycol, a stripping gas 114 having low water content (e.g. a small fraction of the dry natural gas 118) can be injected in the bottom of the still 112 at low pressure and high temperature. This is very efficient for evaporating more water from the regenerated glycol, causing a lower water concentration in the lean glycol than would otherwise be the case.
The now water-desorbed glycol (lean glycol) leaves the still 112 as hot, lean glycol 116, which has a much lower water content than the rich glycol 110. The hot, lean glycol 116 is cooled and is then ready to be mixed with wet natural gas 102 in the absorber column 104 to again absorb water.
The type of glycol conventionally used for topside dehydration processes is TEG (triethyleneglycol). Alternatively, DEG (diethyleneglycol) or MEG (monoethyleneglycol) can be used.
It has been proposed to utilise subsea developments for hydrocarbon processing, rather than surface platforms, in order to reduce costs and topside platform size. For example, WO 2015/018945 broadly proposes a subsea processing facility in which glycol is used subsea to dry a gas-phase hydrocarbon stream to sales gas specifications. In this document, a subsea processing facility is disclosed that includes all of the standard gas processing stages that would otherwise be performed topside to produce a sales gas. The facility particularly includes a subsea glycol scrubber that removes water from the gas stream, and internally provides for full, subsea regeneration of the glycol using gas stripping by a portion of the processed gas (as in FIG. 1). “Make-up” glycol is supplied from topside/onshore, via an umbilical, in order to compensate for losses of glycol to the gas and liquid phases leaving the facility, but the subsea facility is essentially self-contained.
Whilst, in principle, such a facility could be constructed subsea, the number of subsea processing units is traditionally kept low, and the units themselves of reduced complexity, in order to minimise maintenance and reduce the risk of malfunctions.
In order to make gas dehydration processes, such as that illustrated in FIG. 1, more suitable to be used at a subsea installation, it has been proposed that the absorber column 104 be replaced by a system of mixers or contactors, where the natural gas and glycol meet co-currently, and that the relatively complex glycol regeneration process continue to be performed topside or onshore. A subsea dehydration facility incorporating this concept is shown in FIG. 2. Full details of its operation are described in WO 2014/079515.
In this process, a lean glycol stream 191, which is supplied from a topside/onshore glycol regeneration facility, is injected into a natural gas stream 108 and then separated from the gas stream 108 by a scrubber 131. In order to dry the gas stream 108 sufficiently to meet rich gas pipeline transportation specifications, it is a prerequisite that the glycol in stream 191 has been regenerated to a very high concentration, either at a topside facility, or on shore.
MEG is the preferred glycol used in the subsea process illustrated in FIG. 2. This is because the rich MEG exiting in stream 161 (which first has been used to dehydrate the gas stream 108) can act as a hydrate inhibitor when mixed with the water-rich liquid phase hydrocarbon stream 133, ensuring that no hydrates occur in the liquid phase stream on its way to a processing facility. However, most existing MEG-regeneration facilities only regenerate MEG to a purity of around 90 wt %, whereas for sufficient dehydration of the gas stream 108 to meet rich gas pipeline specifications, the purity of the lean MEG must be considerably higher than 90 wt %, and ideally about 98 wt %. Regeneration of MEG to these purities is possible, but requires additional processing after conventional MEG regeneration, such as the gas stripping described above in reference to FIG. 1. This consumes valuable topside platform space and increases the costs for implementing the system in an offshore location due to the additional topside modifications required.
TEG is an alternative glycol that can be used in this system. Existing TEG regeneration units can easily regenerate TEG to a purity of around 99.5 wt %, which is sufficient purity for use as a desiccant to achieve the required gas dryness. Furthermore, TEG is more commonly used at offshore locations than MEG. However, TEG is highly viscous at low temperature and high concentration, which can lead to distribution problems due to the high pressure drop when pumping high purity, lean TEG to the subsea station.
At least the preferred embodiments of the present invention seek to address these problems.